Monitored 130 days of success with Eagle Ford Pilot Test #1, which
supports downspacing in Eagle Ford East

Achieving substantial progress in well performance and cost
efficiencies

October 27, 2015 06:30 PM Eastern Daylight Time

DENVER--(BUSINESS WIRE)--SM Energy Company (NYSE: SM) announces its financial results for the
third quarter of 2015 and provides an operations update. In conjunction
with this release, the Company posted an investor presentation with
additional third quarter earnings and operations detail to the Company's
website at www.sm-energy.com.
This presentation will be referenced during the conference call
scheduled for 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) on
October 28, 2015. Information for the call can be found below.

MANAGEMENT COMMENTARY

Comments from President and Chief Executive Officer Jay Ottoson: "I am
pleased to report another excellent quarter with production and EBITDAX
that exceeded our internal forecasts. Third quarter production was up
sequentially from the second quarter (adjusted for assets sold in the
second quarter) and up 22% compared with the third quarter last year.

"Operational execution continues to drive our outperformance. We are
working hard to reduce costs and apply technology effectively on a
number of fronts. We are reducing drilling times, optimizing completions
and generating better well results in our core development programs. For
example, drilling and completion costs for our operated Eagle Ford wells
in the third quarter were down nearly 50% from our 2014 average. At the
same time, we have been conducting several pilot tests in high
productivity areas of the Eagle Ford and Bakken/Three Forks intended to
prove up additional economic drilling inventory. Test results to date
have been positive and have translated into higher than forecast
production.

"Looking into 2016, we plan to focus our activity on our programs that
generate the best returns. Our diligent efforts to reduce costs and
improve well performance will continue, and we expect to allocate an
increased portion of capital to the Permian and Williston Basins.
Fundamental to the 2016 operating plan will be aligning capital spending
with estimated EBITDAX to optimize cash flow and inventory expansion,
resulting in differential value creation in 2016."

THIRD QUARTER 2015 RESULTS

Production for the third quarter of 2015 was 16.1 MMBOE, or 174.5
MBOE/d, up 22% compared with 13.1 MMBOE, or 142.5 MBOE/d, in the third
quarter of 2014. Total production increased sequentially, adjusted for
second quarter assets sales, and exceeded the Company's expectations by
approximately 0.6 MMBOE, despite an 11% sequential decline in
non-operated Eagle Ford production.

Strong production was driven by well performance in the Company's core
areas that continues to exceed the Company's year-end 2014 type curves
plus a number of positive test wells in the Eagle Ford that came on
sales during the quarter. Specifically, Eagle Ford Test #1 reached a
peak natural gas rate of 105 MMcf/d during the quarter and Test #3 is on
sales with several wells producing more than 10 MMcf/d each, while still
cleaning up. Of note, these tests were drilled in high natural gas
content areas, increasing the mix of natural gas in total third quarter
production. The production mix for the quarter was 28% oil, 45% natural
gas and 27% natural gas liquids ("NGLs"). For the first nine months of
2015, total production was 49.3 MMBOE, up 27% compared with 39.0 MMBOE
in the first nine months of 2014.

Sequential Production

Production

3Q15

2Q15*

Oil Production (MMBbls)

4.5

5.1

Gas Production (Bcf)

43.3

40.3

NGL Production (MMBbls)

4.3

4.0

Total Production (MMBOE)

16.1

15.8

Equivalent Daily Production (MBOE/d)

174.5

173.6

*2Q15 production adjusted for asset sales completed during that
quarter.

Pricing in the third quarter of 2015 reflected a 52% decline in WTI oil
prices, a 30% decline in NYMEX natural gas prices and a 54% decline in
OPIS NGL prices from the prior year period. The Company had
approximately 48% of oil production, 34% of natural gas production and
40% of NGL production hedged during the quarter. The table below
provides the average realized prices received by product, as well as the
adjusted prices received after taking into account settlements for
derivative transactions:

Average Realized Commodity Prices for the Three Months Ended
September 30, 2015

Before the effect ofderivative settlements

After the effect ofderivative settlements

Oil ($/Bbl)

$40.03

$60.05

Gas ($/Mcf)

$2.77

$3.22

Natural gas liquids ($/Bbl)

$15.18

$16.12

Equivalent ($/BOE)

$22.84

$29.92

Operating costs in the third quarter of 2015 included lease operating
expenses of $3.86 per BOE, down $0.72 per BOE from the prior year
period, and transportation expenses of $6.27 per BOE, up $0.05 per BOE
from the prior year period. Lease operating expenses on the Company’s
operated properties tracked internal forecasts and included planned
higher workover expenses compared with the second quarter of 2015. Third
quarter lease operating expenses at the Company’s non-operated Eagle
Ford properties increased Company-wide lease operating expenses $0.20
per BOE sequentially. For the first nine months of 2015, lease operating
expenses averaged $3.70 per BOE and transportation costs averaged $5.99
per BOE, down 13% and 4%, respectively.

General and administrative expenses for the third quarter of 2015 were
$37.8 million, or $2.35 per BOE. Net of non-cash compensation expenses
of $5.4 million, general and administrative expenses were $32.4 million,
or $2.02 per BOE. General and administrative expenses per BOE were down
significantly compared with the prior year periods, down 26% in the
third quarter and down 15% in the first nine months.

Net income for the third quarter of 2015 was $3.1 million, or $0.05 per
diluted common share, compared with net income of $208.9 million, or
$3.05 per diluted common share, in the third quarter of 2014. For the
first nine months of 2015, the Company's net loss was $107.5 million, or
$1.59 per diluted common share, compared with net income of $334.3
million, or $4.90 per diluted common share, in the prior year period.

Adjusted net loss for the third quarter of 2015 was $23.3 million, or
$0.34 per diluted common share, compared with adjusted net income of
$98.6 million, or $1.44 per diluted common share, in the third quarter
of 2014. Lower adjusted net income is predominantly due to the 51%
decline in average prices received per BOE, partially offset by the 22%
increase in production and 15% decrease in production costs per BOE.
Adjusted net income excludes certain items that the Company believes
affect the comparability of operating results and are generally items
whose timing and/or amount cannot be reasonably estimated.

Adjusted earnings before interest, taxes, depletion, amortization and
accretion, and exploration expense, or adjusted EBITDAX, was $259.4
million for the third quarter of 2015, compared with $406.2 million in
the third quarter of 2014. Lower adjusted EBITDAX is primarily a result
of significantly lower commodity prices in the third quarter of 2015,
partially offset by higher production and lower costs per BOE, as
discussed above.

Adjusted net income and adjusted EBITDAX are non-GAAP financial
measures. Please refer to the respective reconciliations in the
Financial Highlights section at the end of this release for additional
information about these measures.

CAPITAL, OPERATIONS AND GUIDANCE

Capital Expenditures

The Company’s total 2015 capital expenditures are estimated at
approximately $1.28 billion. Capital expenditures through the first nine
months totaled approximately $1.1 billion.

The Company's 2015 drilling program is primarily focused on its Eagle
Ford shale and Bakken/Three Forks plays. Third quarter of 2015 capital
expenditures were $277 million, down approximately 18% from the second
quarter of 2015, as the Company reduced its drilling activity from nine
rigs at the end of the second quarter to seven rigs currently. The
Company's seven active operated rigs include four in the Eagle Ford, two
in the Bakken/Three Forks and one in the Powder River Basin. At
year-end, the Company anticipates releasing one rig from its Eagle Ford
program and adding one rig in the Permian Basin. The Company is
currently deferring most completions in both its Eagle Ford and
Bakken/Three Forks programs and plans to increase completion activity
around year-end.

Eagle Ford

Third quarter of 2015 net production averaged 134.5 BOE/d, including
both operated and non-operated wells. Daily production increased 31%
from the third quarter of 2014 and increased 3% sequentially from the
second quarter of 2015, despite an 11% sequential decline in
non-operated production from the area.

The focus on operational execution in the operated Eagle Ford is
resulting in a number of quantifiable results. For example, comparison
of third quarter of 2015 data with 2014 full year averages shows a 54%
decline in completion costs per lateral foot and a 28% reduction in
drilling costs per lateral foot. The average days from spud-to-rig
release per 1,000 feet of total measured depth improved approximately
14% in the program.

The Company has scheduled nine Eagle Ford multi-well pilot tests
intended to test the potential for inventory expansion across its
acreage position through downspacing, infill drilling and the addition
of the Upper Eagle Ford interval. Wells have been drilled and completed
in five of the nine tests, with the remaining tests expected to be
completed in 2016. To date, Eagle Ford test results are encouraging. On
Test #1, a 14-well test of downspacing to 450 feet, the Company has
approximately 130 days of sales. This successful test to date provides
the Company with confidence that future drilling programs in the East
Area can support 450 foot well-spacing. Test #3, a 5-well test of the
Upper and Lower Eagle Ford intervals, includes 312 foot plan-view
spacing. While this test is in a dry natural gas area, its broader
implications are important as to date it appears to extend the footprint
of the Company's Upper Eagle Ford to the south and support the potential
for higher density plan-view spacing throughout the Company's 250-350
foot thick Eagle Ford shale position. Tests #2 through #5 are completed
and either on flowback or have too few days of production to report.

Bakken/Three Forks

Third quarter of 2015 production from the Company's Bakken/Three Forks
program averaged 22.2 MBOE/d and was 85% oil. Production increased 27%
from the third quarter of 2014 and decreased 7% sequentially, as the
Company continues to actively drill in the area but not complete all
wells drilled. As of the end of the third quarter of 2015, the Company
had an inventory of 47 gross and 39 net operated wells drilled and
uncompleted in the area.

The Company's operations have focused on drilling and completion
efficiencies. Drilling days in 2015 are down 11% on average from 2014
and the Company recently drilled a Divide County Bakken well, spud to
rig release, in 10 days. Enhanced completions are driving 20%-30%
increased recoveries per well as the Company employs
plug-and-perf/cemented liner completions. Overall, costs in the area
have been reduced by 20%-25% per well compared with similar wells in
2014.

Cumulative production from nine wells in Divide County, North Dakota
testing the Bakken interval continues to perform above the Company's
type curve expectations for the Three Forks interval, demonstrating the
economic viability of Bakken locations in the area. Two additional
Bakken wells were recently completed farther south on the Company's
acreage, which could expand the potential of the Bakken interval to the
south. The addition of the Bakken interval has the potential to
significantly increase the Company's proved reserves and the inventory
of drilling locations in Divide County.

Guidance

The Company has slightly modified full year 2015 guidance to narrow
certain ranges. In addition, the Company has slightly increased the
mid-point of production guidance and has slightly lowered the mid-point
of transportation and ad valorem tax cost guidance. The following table
presents updated production and performance guidance for full year 2015:

Revised Guidance for 2015

FY2015

Production (MMBOE)

63.6 - 64.4

Average daily production (MBOE/d)

174 - 176

LOE ($/BOE)

$3.70 - $3.90

Ad Valorem ($/BOE)

$0.45 - $0.50

Transportation ($/BOE)

$6.10 - $6.25

Production taxes (% of pre-derivative oil, gas, and NGL revenue)

4.5% - 5.0%

G&A - Cash ($/BOE)

$2.40 - $2.70

G&A - Non-cash ($/BOE)

$0.30 - $0.40

Total G&A ($/BOE)

$2.70 - $3.10

DD&A ($/BOE)

$13.75 - $14.25

Effective income tax rate range

39.6% - 40.6%

FINANCIAL POSITION AND LIQUIDITY

The Company ended the third quarter of 2015 with long-term debt of $2.53
billion, including $2.35 billion in senior notes and $0.18 billion drawn
on its revolving credit facility. As previously reported, under the
Company’s credit facility, the borrowing base is $2.0 billion and
aggregate commitments are $1.5 billion, providing the Company with ample
liquidity.

The Company has commodity derivative contracts in place for the fourth
quarter of 2015 representing approximately 43% of oil, 45% of natural
gas and 48% of NGL forecast volumes at the midpoint, and for 2016
representing approximately 30% of oil, 50% of natural gas and 50% of
NGL, assuming 2015 exit rate production. A summary of commodity
derivative contracts through 2016 are as follows:

Derivative Position through 2016

as of October 21, 2015*

Oil

Gas

NGL***

Period

Volume(MBbls)

Weighted Avg.Price**($/Bbl)

Volume(BBTU)

Weighted Avg.Price**($/MMBTU)

Volume(MBbls)

Weighted Avg.Price - MontBelvieu($/Bbl)

4Q15

2,006

$87.92

17,656

$4.07

1,709

$21.58

1Q16

1,868

$86.93

23,341

$3.90

2,250

$15.67

2Q16

1,752

$86.73

20,780

$3.39

2,018

$15.71

3Q16

1,170

$90.29

18,829

$3.33

1,613

$14.22

4Q16

780

$90.05

17,236

$3.83

1,280

$13.32

* Includes all commodity derivative contracts for settlement at any
time during the fourth quarter of 2015 and later periods, entered
into as of 10/21/15.

** Weighted average prices are shown as NYMEX equivalents. For
collars, floor prices were used to calculate the weighted average
price.

The Company has scheduled a webcast and conference call to discuss third
quarter 2015 financial and operational results. The webcast is scheduled
for October 28, 2015, at 8:00 a.m. Mountain time (10:00 a.m. Eastern
time). The webcast can be accessed from the Company's website at www.sm-energy.com,
and will remain available for replay for approximately 30 days. You may
also join via teleconference at the dial-in information below. A
telephonic replay of the call will be available approximately two hours
after the call through November 11, 2015.

Call Type

Phone Number

Conference ID

Domestic Participant

877-303-1292

57682556

Domestic Replay

855-859-2056

57682556

International Participant

315-625-3086

57682556

International Replay

404-537-3406

57682556

INFORMATION ABOUT FORWARD LOOKING STATEMENTS

This release contains forward looking statements within the meaning of
securities laws, including forecasts and projections. The words
“anticipate,” “assume,” “believe,” “budget,” “estimate,” “expect,”
“forecast,” “intend,” “plan,” “project,” “will” and similar expressions
are intended to identify forward-looking statements. These statements
involve known and unknown risks, which may cause SM Energy's actual
results to differ materially from results expressed or implied by the
forward-looking statements. These risks include factors such as the
availability, proximity and capacity of gathering, processing and
transportation facilities; the volatility and level of oil, natural gas,
and natural gas liquids prices, including any impact on the Company’s
asset carrying values or reserves arising from price declines;
uncertainties inherent in projecting future rates of production or other
results from drilling and completion activities; the imprecise nature of
estimating oil and gas reserves; uncertainties inherent in projecting
future drilling and completion activities, costs or results, including
from pilot tests; the uncertainty of negotiations to result in an
agreement or a completed transaction; the uncertain nature of
divestiture, joint venture, farm down or similar efforts and the ability
to complete any such transactions; the uncertain nature of expected
benefits from the actual or expected divestiture, joint venture, farm
down or similar efforts; the availability of additional economically
attractive exploration, development, and acquisition opportunities for
future growth and any necessary financings; unexpected drilling
conditions and results; unsuccessful exploration and development
drilling results; the availability of drilling, completion, and
operating equipment and services; the risks associated with the
Company's commodity price risk management strategy; uncertainty
regarding the ultimate impact of potentially dilutive securities; and
other such matters discussed in the “Risk Factors” section of SM
Energy's 2014 Annual Report on Form 10-K, as such risk factors may be
updated from time to time in the Company's other periodic reports filed
with the Securities and Exchange Commission. The forward-looking
statements contained herein speak as of the date of this announcement.
Although SM Energy may from time to time voluntarily update its prior
forward-looking statements, it disclaims any commitment to do so except
as required by securities laws.

ABOUT THE COMPANY

SM Energy Company is an independent energy company engaged in the
acquisition, exploration, development, and production of crude oil,
natural gas, and natural gas liquids in onshore North America. SM Energy
routinely posts important information about the Company on its website.
For more information about SM Energy, please visit its website at www.sm-energy.com.

SM ENERGY COMPANY

FINANCIAL HIGHLIGHTS (unaudited)

September 30, 2015

Production Data

For the Three Months Ended September 30,

For the Nine Months Ended September 30,

2015

2014

Percent Change

2015

2014

Percent Change

Average realized sales price, before the effects of derivative
settlements:

Oil (per Bbl)

$

40.03

$

86.56

(54)%

$

43.43

$

89.08

(51)%

Gas (per Mcf)

2.77

4.49

(38)%

2.69

4.86

(45)%

NGL (per Bbl)

15.18

34.86

(56)%

16.20

36.34

(55)%

Equivalent (per BOE)

$

22.84

$

47.06

(51)%

$

24.36

$

48.63

(50)%

Average realized sales price, including the effects of
derivative settlements:

(1) Adjustments are shown net of tax and are calculated
using a tax rate of 36.8% for the three and nine months ended
September 30, 2015, and 37.2% for the three and nine months ended
September 30, 2014, which approximates the Company's statutory tax
rate for the respective periods, as adjusted for ordinary
permanent differences.

(2) Derivative settlement gain (loss) is reported net
of the change in accrued settlements between periods in the
derivative cash settlements line item on the condensed
consolidated statements of cash flows within net cash provided by
operating activities.

(3) For the three and nine-month periods ended
September 30, 2015, the adjustment is related to the impairment of
materials inventory and an estimated adjustment relating to claims
on royalties on certain Federal and Indian leases, which are
included in other operating expenses on the Company's condensed
consolidated statements of operations. For the three and
nine-month periods ended September 30, 2014, adjustments include
items related to settlements from the previously disclosed
litigation against Endeavour Operating Corporation. These items
are included as a portion of other operating revenues and
non-operating expense, other, net, on the Company's condensed
consolidated statements of operations.

(4) Adjusted net income excludes certain items that the
Company believes affect the comparability of operating results and
generally are items whose timing and/or amount cannot be
reasonably estimated. These items include non-cash adjustments and
impairments such as the change in the Net Profits Plan liability,
derivative (gain) loss net of derivative settlements, impairment
of properties, and (gain) loss on divestiture activity. The
non-GAAP measure of adjusted net income is presented because
management believes it provides useful additional information to
investors for analysis of SM Energy's fundamental business on a
recurring basis. In addition, management believes that adjusted
net income is widely used by professional research analysts and
others in the valuation, comparison, and investment
recommendations of companies in the oil and gas exploration and
production industry and many investors use the published research
of industry research analysts in making investment decisions.
Adjusted net income should not be considered in isolation or as a
substitute for net income (loss), income (loss) from operations,
cash provided by operating activities or other income,
profitability, cash flow, or liquidity measures prepared under
GAAP. Since adjusted net income excludes some, but not all, items
that affect net income and may vary among companies, the adjusted
net income amounts presented may not be comparable to similarly
titled measures of other companies.

(5) For periods where the Company reports a GAAP net
loss, the diluted weighted average share count is calculated using
potentially dilutive securities related to unvested Restricted
Stock Units and contingent Performance Share Units. On a GAAP
basis, these items are not treated as dilutive securities in
periods where the Company reports a GAAP loss for the period.
Additionally, in periods where an adjusted net loss is calculated,
all potentially dilutive shares are anti-dilutive and excluded
from the calculation of adjusted net loss per diluted common share.

(1) Stock-based compensation expense is a component of
exploration expense and general and administrative expense on the
accompanying condensed consolidated statements of operations.
Therefore, the exploration line items shown in the reconciliation
above will vary from the amount shown on the accompanying condensed
consolidated statements of operations because of the component of
stock-based compensation expense recorded to exploration.

(2) Derivative settlement gain (loss) is reported net of
the change in accrued settlements between periods in the derivative
cash settlements line item on the condensed consolidated statements
of cash flows within net cash provided by operating activities.

(3) Adjusted EBITDAX represents income (loss) before
interest expense, other non-operating income or expense, income
taxes, depreciation, depletion, amortization, and accretion expense,
exploration expense, property impairments, non-cash stock based
compensation expense, derivative gains and losses net of
settlements, change in the Net Profits Plan liability, and gains and
losses on divestitures. Adjusted EBITDAX excludes certain items that
the Company believes affect the comparability of operating results
and can exclude items that are generally one-time in nature or whose
timing and/or amount cannot be reasonably estimated. Adjusted
EBITDAX is a non-GAAP measure that is presented because the Company
believes that it provides useful additional information to investors
and analysts, as a performance measure, for analysis of the
Company's ability to internally generate funds for exploration,
development, acquisitions, and to service debt. The Company is also
subject to a financial covenant under its credit facility based on
its debt to adjusted EBITDAX ratio. In addition, adjusted EBITDAX is
widely used by professional research analysts and others in the
valuation, comparison, and investment recommendations of companies
in the oil and gas exploration and production industry, and many
investors use the published research of industry research analysts
in making investment decisions. Adjusted EBITDAX should not be
considered in isolation or as a substitute for net income (loss),
income (loss) from operations, net cash provided by operating
activities, or profitability or liquidity measures prepared under
GAAP. Because adjusted EBITDAX excludes some, but not all items that
affect net income and may vary among companies, the adjusted EBITDAX
amounts presented may not be comparable to similar metrics of other
companies.